When producing oil and/or gas from an unconsolidated subterranean formation, some type of particulate control procedure may be required in order to prevent sand grains and/or other formation fines from migrating into the well bore and being produced from the well. The production of such particulate materials can reduce the rate of hydrocarbon production from the well and can cause serious damage to well tubulars and to well surface equipment.
Those skilled in the art have commonly used gravel packs to control particulate migration in producing formations. A gravel pack will typically consist of a mass of sand and/or gravel which is placed around the exterior of a screening device, said screening device being positioned in an open hole or inside a well casing. Examples of typical screening devices include wire-wrapped screens and slotted liners. The screening device will typically have very narrow slots or very small holes formed therein. These holes or slots are large enough to permit the flow of formation fluid into the screening device but are too small to allow the gravel/sand constituents of the gravel pack to pass therethrough. In conjunction with the operation of the holes or slots formed in the screening device, the gravel/sand constituents of the gravel pack operate to trap, and thus prevent the further migration of, particulate materials which would otherwise be produced along with the formation fluid.
Unfortunately, the installation of gravel packs in underground formations can be quite costly. Additionally, special equipment is required for installing gravel packs.
Another technique used to control particulate migration in producing formations involves the use of chemical consolidation treatments. Chemical consolidation treatments can also be quite costly. Further, these treatments require the use of special chemicals and equipment.
Nonpermeable foamed cement compositions have been used heretofore in oil and gas wells for performing various primary cementing operations. Nonpermeable foamed cement compositions are formed by introducing nitrogen, air, or some other gas into a cement slurry. Compared to non-foamed cement compositions, nonpermeable foamed cement compositions typically have low densities and low fluid loss properties.
In performing a primary cementing operation using either a nonpermeable foamed cement composition or some other type of nonpermeable cement slurry composition, the cement composition is pumped down a casing disposed in a well bore such that, when the cement slurry reaches the bottom of the casing, the cement slurry flows up and into the annulus existing between the exterior of the well casing and the earthen wall of the well bore. Upon setting, the nonpermeable cement composition bonds to the casing and to the well bore such that (1) the casing is rigidly supported within the well bore and (2) fluid flow within the cemented portion of the annulus is prevented.
Due to their low densities, nonpermeable foamed cement compositions can be advantageously used in primary cementing operations where it is necessary to minimize hydrostatic pressure effects on weak formations and/or to lift primary cement columns over long annular intervals. Additionally, compared to nonfoamed cement compositions, nonpermeable foamed cement compositions typically have high compressibilities. Due to their high compressibilities, nonpermeable foamed cements are resistant to the incursion of pressurized formation gases into and around the cement composition during the primary cementing operation (i.e., before the cement composition has set).
As is well known in the art, a high deviation well, e.g., a horizontally completed well, can be drilled when it is desirable to obtain a well bore which is not strictly vertical. As used herein and in the claims, the term "high deviation well" refers to any well having a well bore which is intentionally drilled such that one or more portions of the well bore are nonvertical. A high deviation well bore can be drilled, for example, when it is desirable to direct the well bore around, to, or through a given formation. The term "horizontally completed well," as used herein, refers to a well wherein the well bore has been drilled to include one or more substantially horizontal sections.
Subterranean formations, although typically very thin, can extend great distances horizontally. Thus, although the bore of a strictly vertical well would extend only a few feet through a typical thin formation, a horizontally completed well can include one or more horizontal well bore sections which extend several hundred or several thousand feet through the formation. By providing much greater contact between the well bore and the formation, the horizontally completed well can provide a higher production rate than would be provided by a strictly vertical well.
In one technique commonly used for completing high deviation wells, a casing is installed in only the substantially vertical initial portion of the well bore. Consequently, formation fluid flows freely into the uncased horizontal portion of the well and is then recovered through the vertical well casing. Unfortunately, the uncased horizontal portion of the well will typically be highly susceptible to cave-ins and sloughing, particularly when the formation through which the horizontal section of the well bore runs is a significantly unconsolidated formation. Additionally, the level of particulate migration occurring in the uncased horizontal portion of a horizontally completed well can be quite high. As discussed above, particulate migration can reduce the hydrocarbon production rate from the well and can cause serious damage to well tubulars and surface equipment.
A second technique commonly used for completing horizontal wells involves placing a length of slotted liner or casing in the horizontal portion of the well. The slotted liner or casing operates to prevent the horizontal portion of the well from collapsing. In order to prevent particulate migration into the slotted liner or casing, a gravel pack can be placed around the exterior of the liner or casing in the same manner as described hereinabove. However, as also discussed above, the installation of a gravel pack can be quite costly, particularly when the gravel pack must extend several hundred or several thousand feet along the horizontal portion of a horizontally completed well.
A third technique commonly used for completing horizontal wells involves placing and cementing a casing in both the vertical and horizontal portions of the well bore. Perforations or sliding sleeve valves must be placed along the horizontal portion of the casing in order to allow the casing to communicate with the producing formation. The formation is typically fractured through these casing perforations or valves. Unfortunately, however, this system typically does not provide adequate protection against the migration of formation particulates into the well casing. Additionally, the perforating operation itself may promote the disconsolidation of the formation. Further, in a highly deviated well, it is typically not desirable to place cement across the productive interval of a naturally fractured formation since the cement will block the horizontal flow of fluid from the natural fractures to the casing perforations or valves.
In view of the above comments, it is evident that a problem of longstanding existing in the completion of wells in subterranean formations having a substantial degree of unconsolidation resides in the need to reduce, if not prevent, the migration of formation particles from the formation to the production tubing and surface equipment without, at the same time, reducing the flow of desired fluids, e.g., oil and/or gas, from the formation. This problem is difficult enough when the borehole is substantially vertical, but it is even more difficult when the borehole is highly deviated or is, in fact, horizontal.
It is understood that producing formations cannot be blocked, such as by primary cementing, because cements ordinarily employed in primary cementing have very low permeability, e.g., less than about 0.001 darcies, which would prevent the flow of desirable fluids from the formation to the production equipment. Accordingly, producing formations penetrated by a borehole are usually not cemented and migration of formation particulates from unconsolidated formations is reduced, or prevented, as above discussed, chemically, by employing a formation consolidation technique, or, mechanically, by employing a gravel packing technique. The above techniques have been used successfully in completing a substantially vertical borehole wherein the portion of the borehole which does not penetrate a producing formation can be cemented to thereby support the casing and isolate and protect producing formations, while unconsolidated producing formations penetrated by the same borehole can be chemically or mechanically treated, as mentioned above, to reduce or prevent fines migration while not blocking the flow desirable fluids.
In contrast with a vertical borehole, a borehole, or a very long portion of one, which lies entirely within a producing formation, such as a horizontal borehole, requires the use of a completion technique which will function to maintain the structural integrity of the borehole itself, i.e., prevent collapse, which will not prevent the flow of desirable fluids from the formation to the production tubulars. Known cements would maintain structural integrity of the borehole but would also prevent flow of desired fluids. Chemical and mechanical treatments, as above described, would not prevent the flow of desired fluids but are very difficult to install in highly deviated boreholes and the ability of such treatments to provide adequate structural integrity has not been established.
Accordingly, the art requires a method which will supply the structural integrity provided by primary cementing; which will control, where required, the movement of formation fines; and which will not prevent the flow of desired fluids from the formation to the production tubulars. This invention provides such a method which features the use of a cement having a permeability low enough to prevent migration of formation particulates but high enough to permit the flow of desired fluids through the hardened cement to production tubulars. The cement develops sufficiently high compressive strength to support and protect formations but is also of sufficiently low density to permit use in weak formations. This cement and the method disclosed is, accordingly, useful in vertical as well as in highly deviated and horizontal boreholes.
As is known in the art, hydraulic fracturing techniques are commonly used to stimulate subterranean formations in order to enhance the production of fluids therefrom. In a conventional hydraulic fracturing procedure, a fracturing fluid is pumped down a well bore and into a fluid-bearing formation. The fracturing fluid is pumped into the formation under a pressure sufficient to enlarge natural fissures in the formation and/or open up new fissures in the formation. Packers can be positioned in a well bore as necessary to direct and confine the fracturing fluid to the portion of the well which is to be fractured. Typical fracturing pressures range from about 1,000 psi to about 15,000 psi depending upon the depth and the nature of the formation being fractured.
Fracturing fluids used in conventional hydraulic fracturing techniques include: fresh water; brine; liquid hydrocarbons (e.g., gasoline, kerosene, diesel oil, crude oil, and the like) which are viscous or have gelling agents incorporated therein; gelled water; and gelled brine. The fracturing fluid will also typically contain a propping agent. Commonly used propping agents include solid particulate materials such as sand, walnut shells, glass beads, metal pellets, plastics, and the like. The propping agent flows into and remains in the fissures which are formed and/or enlarged during the fracturing operation. The propping agent operates to prevent the fissures from closing and thus facilitates the flow of formation fluid through the fissures and into the well bore.
Unconsolidated and poorly consolidated formations typically require some type of stimulative treatment in order to be commercially productive. Such formations typically contain packed sands and fine particulate materials which tend to migrate within the formation as fluid is recovered therefrom. Such migration can substantially reduce the fluid conductivity of the formation.
Conventional hydraulic fracturing techniques have generally not been effective in unconsolidated formations. An unconsolidated formation will typically have little or no structural strength. When the formation is subjected to a conventional hydraulic fracturing procedure, the particulate material contained in the formation tends to move and reconsolidate. Consequently, a substantial quantity of the particulate material becomes mixed with the proppant and thereby reduces the permeability of the proppant bed. Alternatively, the proppant material will sometimes simply become embedded in the formation. Further, due to the typically high initial permeability of an unconsolidated formation, the fluid component of a fluid/proppant mixture will tend to separate from the proppant and leak into the formation. When such separation occurs, a sufficient hydraulic fracture width typically will not be established in the formation to pass and transport the proppant material. As a result, the proppant material will not be placed in created fissures at sufficient distances from the borehole and in sufficient concentrations to yield a substantial increase in flow capacity.
As will also be apparent, many commonly used conventional fracturing fluids contain components which are not suitable for use in potable water-containing formations.
Hydraulic fracturing operations have also been conducted using resin-coated particulate materials (e.g., resin-coated sand) as propping agents. Typical resin materials used for forming such coated proppants include epoxy resins and polyepoxide resins. Once in place in the formation, the resin material is allowed to harden whereby the resin-coated particulate material consolidates to form a hard permeable mass. The resin-coated particulate material will typically be carried into the formation using an aqueous gelled carrier fluid.
Unfortunately, resin-coated proppants are very expensive to use. Fracturing fluids utilizing resin-coated proppants also typically contain materials (e.g., alcohols, polyalcohols, amine hardeners, metallic crosslinkers, and the resins themselves) unsuitable for use in stimulating potable water-containing formations. Additionally, when the fracturing fluid is in place in the formation and the pumping operation is discontinued, the resin-coated particulate material will typically settle within the gelled aqueous carrier fluid to some degree before the resin hardens. As a result of this settling, voids are formed in the resin matrix. Further, the gelling agents (e.g., polysaccharides such as guar and guar derivatives) used in these fracturing fluids can form residues in the resin matrix and in the surrounding formation which reduce fluid conductivity. Finally, fracturing fluids containing resin-coated proppants are not suitable for use in some weak formations which cannot withstand the hydrostatic pressures typically exerted by sand laden slurries.
Aldrich, C. H. and Mitchell, B. J., "Strength, Permeabilities, and Porosity of Oilwell Foam Cement," Journal of Engineering for Industry, 1975 discloses foamed cement compositions consisting of API class G cement, a surfactant, water, and air. The authors of this article indicate that such cement compositions can be formed to have either (1) high permeabilities with small interconnected pores and high strength or (2) light weight with disconnected pores or interconnected pores and high strength. The authors speculate that foamed cement compositions might be useful for sand control in oil or gas wells. The authors further speculate that foamed cement compositions may one day be used in oilwell applications by employing placement practices which might parallel those practices used in normal cementations, sand plasticizing, or hydraulic fracturing. However, the authors go on to indicate that, due to insufficient knowledge in areas such as (1) theological properties, (2) placement techniques, (3) mixing techniques, and (4) the effects of additives, such methods and practices are neither known or understood by those skilled in the art. Thus, the article fails to provide sufficient teaching and direction for achieving the speculative results envisioned therein. Rather, the article simply arouses curiosity and generally encourages further investigation and experimentation.
U.S. Pat. No. 3,654,991 discloses a hydraulic fracturing technique which utilizes a fracturing composition composed of: cement, sand, oil, an oil wetting agent, and an aqueous carrier fluid. When the fracturing composition is in place in the formation, an aqueous surface-active agent is pumped into the fracturing composition in order to displace the oil component of the composition and thereby allow the hydration of the remaining cementitious material. The hydration of the cementitious material results in the formation of a fluid permeable cement barrier within the formation fractures.
Serious shortcomings are also encountered, however, in the use of permeable cementitious fracturing compositions of the type employed in the method of U.S. Pat. No. 3,654,991. These compositions are not suitable for use in weak formations which cannot withstand the hydrostatic pressures typically exerted by sand laden slurties. These compositions also typically contain substantial quantities of oil and other materials which are not suitable for use in stimulating potable water-containing formations. Additionally, the oil contained in these compositions can form emulsion blockages within the formation which can reduce formation productivity. Further, when the composition is in place in the formation, there is a substantial likelihood that a significant portion of the composition will not be contacted and activated by the post flush used in the method of U.S. Pat. No. 3,654,991.
Chemical stimulation treatments are also commonly used to enhance fluid recovery from subterranean formations. In a typical chemical stimulation treatment, an acid or solvent is pumped into the formation to dissolve or otherwise remove materials from the formation and thereby open up flow passages therein.
Unfortunately, chemical stimulation treatments of the type just described can actually cause additional disconsolidation to occur within the formation. Such treatments can also cause the release of additional formation fines. Further, most chemical stimulation compositions contain substantial quantities of acids and/or other substances which cannot be used in potable water-containing formations.
Previous attempts to install water wells in the Dolet Hills sand near Mansfield, Louisiana are illustrative of various problems associated with the formation stimulation techniques heretofore used in the art. We have determined that the Dolet Hills sand is a very poorly consolidated potable water aquifer which is characterized by: a horizontal permeability of about 7.74 darcies; a vertical permeability of about 6.45 darcies; a median sand particle size in the range of from 80 to 120 mesh; and a substantial fines content consisting of particles having sizes of 200 mesh and smaller.
Due to its substantial fines content and highly unconsolidated nature, the sustainable fluid conductivity of the Dolet Hills sand is very low. Thus, if a water well is to be installed in the Dolet Hills sand, some type of stimulation procedure must typically be used in order to obtain a suitable sustained rate of fluid production. However, conventional formation stimulation techniques have not been and/or cannot be successfully used in the Dolet Hills sand. Specifically, it is noted that: (a) the very poorly consolidated nature of the Dolet Hills sand and the mobility of the formation sand under flow render conventional hydraulic fracturing procedures ineffective; (b) since the Dolet Hills sand is a potable water aquifer, stimulation techniques (e.g., chemical stimulation and fracturing with resin-coated proppants) cannot be used since these procedures would introduce contaminants into the formation; and (c) resin-coated particulate systems are also generally too expensive for viable commercial use in such applications.
Thus, in view of the above, it is apparent that a need exists for a well stimulation procedure wherein the well stimulation fluid also acts as a formation stabilizer and/or consolidation aid. A need also exists for such a stimulation procedure wherein the stimulation fluid does not contain materials which would contaminate potable water aquifers and other formations. Additionally, a need exists for such a procedure which is economically viable. Further, a need exists for such a procedure which: (a) will operate to form and fill fissures extending substantial distances from the well bore; (b) will not yield undesirable residues, emulsions, and the like which would reduce formation productivity; and (c) will exert relatively low hydrostatic pressures on weak subterranean formations.